Catalytic cracking is a petroleum refining process that is applied commercially on a very large scale. A majority of the refinery gasoline blending pool in the United States is produced by this process, with almost all being produced using the fluid catalytic cracking process. In the catalytic cracking process heavy hydrocarbon fractions are converted into lighter products by reactions taking place at elevated temperature in the presence of a catalyst, with the majority of the conversion or cracking occurring in the gas phase. This hydrocarbon feedstock is thereby converted into gasoline, distillate and other liquid cracking products as well as lighter gaseous cracking products of four or fewer carbon atoms per molecule. The gas partly consists of olefins and partly of saturated hydrocarbons.
In catalytic cracking processes, hydrocarbon feedstock is injected into the riser section of a hydrocarbon cracking reactor, where it cracks into lighter, valuable products on contacting hot catalyst circulated to the riser-reactor from a catalyst regenerator. As the endothermic cracking reactions take place, heavy material known as coke is deposited onto the catalyst. This reduces the activity of the catalyst and regeneration of the catalyst is desired. The catalyst and hydrocarbon vapors are carrier up the riser to the disengagement section of the reactor, where they are separated. Subsequently, the catalyst flows into the stripping section, where the hydrocarbon vapors entrained with the catalyst are stripped by steam injection. Following removal of occluded hydrocarbons from the spent cracking catalyst, the stripped catalyst flows through a spent catalyst standpipe and into the catalyst regenerator.
Typically, catalyst regeneration is accomplished by introducing air into the regenerator and burning off the coke to restore catalyst activity. These coke combustion reactions are highly exothermic and heat the catalyst. The hot, reactivated catalyst flows through the regenerated catalyst standpipe back to the riser to complete the catalyst cycle. The coke combustion exhaust gas stream rises to the top of the regenerator and leaves the regenerator through the regenerator flue. The exhaust gas generally contains NOx, SOx, CO, oxygen, ammonia, nitrogen and CO2.
The three characteristic steps of the catalytic cracking can therefore be distinguished: 1) a cracking step in which the hydrocarbons are converted into lighter products, 2) a stripping step to remove hydrocarbons adsorbed on the catalyst, and 3) a regeneration step to burn off coke from the catalyst. The regenerated catalyst is then reused in the cracking step.
The catalyst regenerator may be operated in complete combustion mode, which has now become the standard combustion mode, in partial CO combustion mode, or in a dual complete/partial combustion mode. In complete combustion operation, the coke on the catalyst is completely burned to CO2. This is typically accomplished by conducting the regeneration in the presence of excess oxygen, provided in the form of excess air. The exhaust gas from complete combustion operations comprises NOx, SOx, CO2, nitrogen and oxygen.
In partial carbon monoxide combustion mode operation, the catalyst regenerator is operated with insufficient air to burn all of the coke in the catalyst to CO2. As a result, the coke is combusted to a mixture of CO and CO2. The CO can optionally be oxidized to CO2 in a downstream CO boiler. The effluent from the CO boiler comprises NOx, SOx, CO2 and nitrogen.
Several approaches have been used in industry to reduce SOx, NOx and CO in crackling catalyst regenerator exhaust gases. These include capital-intensive and expensive options, such as pretreatment of reactor feed with hydrogen and flue gas post-treatment options, and less expensive options, such as the use of catalysts and catalyst additives.
An early approach used alumina compounds as additives to the cracking catalyst to adsorb sulfur oxides in the FCC regenerator; the adsorbed sulfur compounds that entered the process in the feed were released as hydrogen sulfide during the cracking portion of the cycle and passed to the product recovery section of the unit where they were removed. However, while sulfur is subsequently removed from the stack gases of the regenerator in this process, product sulfur levels are not greatly affected.
It is known in the art that NOx can be removed from the flue gas with NH3, which is a selective reducing agent that does not react rapidly with excess oxygen that may be present in the flue gas. Two types of NH3 processes have evolved, thermal and catalytic. Thermal processes operate as homogeneous gas-phase processes at high temperatures, typically around 1550 to 1900° F. The catalytic systems generally operate at much lower temperatures, typically at 300 to 850° F. U.S. Pat. No. 4,521,389 describes adding NH3 to flue gas to catalytically reduce the NOx to nitrogen. These flue gas treatments to reduce NOx are powerful, but the capital and operating costs are high. Alternative compositions and methods for reducing NOx and CO in the flue gas of an FCC unit are described in co-pending U.S. patent application Ser. No. 10/639,688, filed Aug. 13, 2003.
Industrial facilities are continuously trying to find new and improved methods to reduce the concentration of NOx, SOx and CO from the emission of FCC units to reduce pollution in the atmosphere. The invention is directed to these and other important ends.